Halliburton Energy Services, Inc.

Julian Drew

Mikko K Jaaskelainen

Barry Fish

Benjamin Simon Schaeffer

Crispin Doyle

Cole Aaron Grandjean

Richard Gibson

David Diller

Faraaz Adil

Werner Heigl

A system for determining one or more characteristics of a multiphase fluid flow within a flow line of a hydrocarbon well. The system can include a multiphase flow metering probe, a measurement device, and a computing device. The multiphase flow metering probe may comprise a unitary assembly of components including an optical fiber cable, at least one flow conditioning element, at least one optical sensor, and a mounting component designed to secure the multiphase flow metering probe within the flow line. Signals generated by the at least one optical sensor of the multiphase flow metering probe can be received by the measurement device and subsequently transmitted to the computing device for determining various characteristics of the multiphase fluid flow.

Measurement of multi-phase wellbore fluid

A system can determine multi-phase measurements with respect to a wellbore. The system can include a set of acoustic devices, a measurement device, and a computing device. The set of acoustic devices can be positioned at the surface of a wellbore to generate acoustic signals proportional to flow of fluid with respect to the wellbore. The measurement device can be positioned with respect to the set of acoustic devices to sense the acoustic signals. The computing device can be communicatively coupled to the measurement device to interpret the acoustic signals for determining a type of the fluid and a ratio of one or more phases of the fluid.

Acoustic devices for measuring multi-phase wellbore fluid

A method for configuring a learning machine to predict a flow rate of at least one phase of a fluid. The method comprises determining a feature set for the learning machine, the feature set including information derived from a signal generated by a flow of the fluid interacting with a fluidic oscillator in a wellbore. The method comprises configuring the learning machine with the feature set including information derived from the signal.

Machine learning-based wellbore fluid flow rate prediction

A method for determining flow information of a well producing fluid from a subsurface formation comprising. The method comprises obtaining at least one first production measurement from the well. The method comprises obtaining, with a sensor, a first measurement generated by the fluid flowing through a device. The method comprises inputting the first measurement and the at least one first production measurement into a virtual flow meter. The method comprises determining, via the virtual flow meter, a multi-phase flow rate of the fluid based on the first measurement and the at least one first production measurement.

Virtual flow metering using acoustics for a well

A method can be used to determine multi-phase measurements of fluid flowing with respect to a wellbore. Signals can be received, and the signals can be emitted by each variable frequency acoustic emitter of a set of variable frequency acoustic emitters positioned spaced apart in a sensing transducer that is in an interior of a wellbore. The received signals can be converted into a flow rate of each of a set of different fluid phases of a fluid in the wellbore. The multi-phase measurements of the fluid can be determined using the converted flow rate.

Oil and gas well multi-phase fluid flow monitoring with multiple transducers and machine learning

A system for making multi-phase measurements of a fluid includes a flow meter device and a computing device. The flow meter device can include one or more acoustic devices that can generate acoustic signals in a wellbore. The computing device can receive acoustic signals from the flow meter device and determine an arrangement of the one or more acoustic devices with respect to the wellbore. The computing device can interpret the acoustic signals using the determined arrangement of the one or more acoustic devices to make a multi-phase measurement of fluid with respect to the wellbore.

Determining orientation of a subsurface flow meter device

Multi-phase measurements of a fluid in a wellbore can be received and stored by a memory tool for determining flow characteristics of fluid flowing in the wellbore. A system can include a flow meter device, one or more sensors, and a memory tool The flow meter device can include one or more acoustic devices that can be positioned to generate acoustic signals in a wellbore. The one or more sensors can be positioned to detect the acoustic signals from the flow meter device for making multi-phase measurements of fluid with respect to the wellbore. The memory tool can be communicatively coupled to the one or more sensors to receive and store the multi-phase measurements for a predetermined amount of time for determining flow characteristics of the fluid.

Memory tool for a retrievable flow meter device

An asymmetric fluidic oscillator can generate acoustic signals in a wellbore. The asymmetric fluidic oscillator can include an inlet housing defining an inlet channel, a feedback system, and an outlet housing defining an outlet channel. The inlet channel can be sized to receive fluid from the wellbore. The feedback system can be coupled to the inlet channel to oscillate the fluid from the wellbore. The outlet channel can be coupled to the feedback system and can be sized to receive the oscillated fluid from the feedback system. The outlet channel can include an asymmetric feature to generate acoustic signals detectable in the wellbore.

Asymmetric fluidic oscillator for generating a wellbore signal

A downhole energy harvesting apparatus comprising a fluidic oscillator comprising: an inlet channel configured to receive fluid from a wellbore, a feedback system coupled to the inlet channel to oscillate the fluid, and an outlet channel coupled to the feedback system and configured to receive the oscillated fluid from the feedback system, and at least one piezoelectric element disposed on at least one side of the outlet channel and configured to generate an electric signal in response to variations in pressure of the oscillated fluid.

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Centennial, CO, United States of America

Julian Drew